10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2015

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-03789

Southwestern Public Service Company

(Exact name of registrant as specified in its charter)

New Mexico	75-0575400
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Tyler at Sixth
Amarillo, Texas	79101
(Address of principal executive offices)	(Zip Code)

(303) 571-7511

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨	Accelerated filer ¨
Non-accelerated filer x	Smaller reporting company ¨
(Do not check if smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at May 4, 2015
Common Stock, $1 par value	100 shares

Southwestern Public Service Company meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item l     —	Financial Statements (Unaudited)	3
Item 2    —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 4    —	Controls and Procedures	22
PART II — OTHER INFORMATION
Item 1     —	Legal Proceedings	22
Item 1A  —	Risk Factors	22
Item 4    —	Mine Safety Disclosures	22
Item 5    —	Other Information	23
Item 6    —	Exhibits	23
SIGNATURES		24
Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

This Form 10-Q is filed by Southwestern Public Service Company, a New Mexico corporation (SPS). SPS is a wholly owned subsidiary of Xcel Energy Inc.  Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado, a Colorado corporation (PSCo); and SPS.  NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries.  Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).

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PART 1 — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2015			2014
Operating revenues	$	423,829		$	448,400
Operating expenses
Electric fuel and purchased power	245,799			289,204
Operating and maintenance expenses	73,897			69,398
Demand side management program expenses	3,669			3,064
Depreciation and amortization	35,739			30,512
Taxes (other than income taxes)	14,966			13,646
Total operating expenses	374,070			405,824
Operating income	49,759			42,576
Other (expense) income, net	(56		)	41
Allowance for funds used during construction — equity	1,705			3,640
Interest charges and financing costs
Interest charges — includes other financing costs of $774 and $730, respectively	20,884			19,281
Allowance for funds used during construction — debt	(1,061		)	(2,127		)
Total interest charges and financing costs	19,823			17,154
Income before income taxes	31,585			29,103
Income taxes	11,338			10,368
Net income	$	20,247		$	18,735

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2015		2014
Net income	$	20,247	$	18,735
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $24 for each of the three months ended March 31, 2015 and 2014, respectively	42		43
Other comprehensive income	42		43
Comprehensive income	$	20,289	$	18,778

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2015			2014
Operating activities
Net income	$	20,247		$	18,735
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	36,310			31,059
Demand side management program amortization	418			418
Deferred income taxes	3,617			22,166
Amortization of investment tax credits	(85		)	(85		)
Allowance for equity funds used during construction	(1,705		)	(3,640		)
Net derivative losses	66			66
Changes in operating assets and liabilities:
Accounts receivable	(12,719		)	12,526
Accrued unbilled revenues	26,906			(2,413		)
Inventories	11,482			5,131
Prepayments and other	(12,485		)	(15,455		)
Accounts payable	(21,160		)	9,454
Net regulatory assets and liabilities	29,566			(16,994		)
Other current liabilities	12,521			3,908
Pension and other employee benefit obligations	(10,954		)	(3,513		)
Change in other noncurrent assets	301			2,951
Change in other noncurrent liabilities	378			1,758
Net cash provided by operating activities	82,704			66,072
Investing activities
Utility capital/construction expenditures	(126,622		)	(137,637		)
Allowance for equity funds used during construction	1,705			3,640
Investments in utility money pool arrangement	(9,000		)	(10,000		)
Repayments from utility money pool arrangement	9,000			10,000
Net cash used in investing activities	(124,917		)	(133,997		)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	86,000			(15,000		)
Borrowings under utility money pool arrangement	41,000			231,000
Repayments under utility money pool arrangement	(57,000		)	(169,000		)
Capital contributions from parent	—			40,000
Dividends paid to parent	(27,828		)	(18,082		)
Net cash provided by financing activities	42,172			68,918
Net change in cash and cash equivalents	(41		)	993
Cash and cash equivalents at beginning of period	596			1,011
Cash and cash equivalents at end of period	$	555		$	2,004
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(8,870	)	$	(7,570	)
Cash paid for income taxes, net	(19,004		)	(2,522		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	28,426		$	30,938

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

(amounts in thousands, except share and per share data)

	March 31, 2015			Dec. 31, 2014
Assets
Current assets
Cash and cash equivalents	$	555		$	596
Accounts receivable, net	78,710			71,626
Accounts receivable from affiliates	7,618			1,983
Accrued unbilled revenues	102,381			129,287
Inventories	31,749			43,231
Regulatory assets	48,911			52,006
Derivative instruments	14,350			23,776
Deferred income taxes	79,013			51,854
Prepayments and other	45,554			31,476
Total current assets	408,841			405,835
Property, plant and equipment, net	3,831,044			3,743,141
Other assets
Regulatory assets	314,557			323,305
Derivative instruments	31,191			33,164
Other	15,438			15,859
Total other assets	361,186			372,328
Total assets	$	4,601,071		$	4,521,304
Liabilities and Equity
Current liabilities
Short-term debt	$	123,000		$	37,000
Borrowings under utility money pool arrangement	—			16,000
Accounts payable	140,907			160,762
Accounts payable to affiliates	15,343			19,790
Regulatory liabilities	104,009			87,723
Taxes accrued	19,848			27,208
Accrued interest	27,327			17,057
Dividends payable	25,339			27,828
Derivative instruments	3,565			3,565
Other	88,724			80,211
Total current liabilities	548,062			477,144
Deferred credits and other liabilities
Deferred income taxes	878,653			849,145
Regulatory liabilities	110,867			115,188
Asset retirement obligations	26,369			26,031
Derivative instruments	29,752			30,643
Pension and employee benefit obligations	92,647			103,670
Other	9,553			9,320
Total deferred credits and other liabilities	1,147,841			1,133,997
Commitments and contingencies
Capitalization
Long-term debt	1,349,774			1,349,691
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at March 31, 2015 and Dec. 31, 2014, respectively	—			—
Additional paid in capital	1,165,435			1,165,463
Retained earnings	390,906			395,998
Accumulated other comprehensive loss	(947		)	(989		)
Total common stockholder's equity	1,555,394			1,560,472
Total liabilities and equity	$	4,601,071		$	4,521,304

See Notes to Financial Statements

6

SOUTHWESTERN PUBLIC SERVICE COMPANY

Notes to Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of SPS as of March 31, 2015, and Dec. 31, 2014; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2015 and 2014; and its cash flows for the three months endedMarch 31, 2015 and 2014. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2015 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2014 balance sheet information has been derived from the audited 2014 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014. These notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the financial statements and notes thereto included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014, filed with the SEC on Feb. 23, 2015. Due to the seasonality of SPS’ electric sales, interim results are not necessarily an appropriate base from which to project annual results.

1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the financial statements in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Issued

Revenue Recognition— In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, is effective for interim and annual reporting periods beginning after Dec. 15, 2016. In April 2015, the FASB tentatively decided to defer the effective date by one year, making the guidance effective for interim and annual reporting periods beginning after Dec. 15, 2017. This tentative decision will be exposed for public input in an upcoming proposed ASU with a 30-day comment period. SPS is currently evaluating the impact of adopting ASU 2014-09 on its financial statements.

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. SPS is currently evaluating the impact of adopting ASU 2015-02 on its financial statements.

Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the balance sheets, SPS does not expect the implementation of ASU 2015-03 to have a material impact on its financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	84,817		$	77,465
Less allowance for bad debts	(6,107		)	(5,839		)
	$	78,710		$	71,626

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(Thousands of Dollars)	March 31, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	25,500	$	24,738
Fuel	6,249		18,493
	$	31,749	$	43,231

(Thousands of Dollars)	March 31, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	5,480,750		$	5,376,606
Construction work in progress	248,921			238,519
Total property, plant and equipment	5,729,671			5,615,125
Less accumulated depreciation	(1,898,627		)	(1,871,984		)
	$	3,831,044		$	3,743,141

4. Income Taxes

Except to the extent noted below, Note 6 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in March 2016. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of March 31, 2015, the IRS had proposed an adjustment to several federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. SPS is not expected to accrue any income tax expense related to this adjustment. As of March 31, 2015, the IRS has begun the appeals process; however, the outcome and timing of a resolution are uncertain.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of March 31, 2015, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	March 31, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	1.5	$	1.5
Unrecognized tax benefit — Temporary tax positions	12.3		11.7
Total unrecognized tax benefit	$	13.8	$	13.2

The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)	March 31, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(5.5	)	$	(4.8	)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.

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The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at March 31, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2015 or Dec. 31, 2014.

5. Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

Texas 2015 Electric Rate Case — In December 2014, SPS filed a retail electric, non-fuel rate case in Texas seeking an overall increase in annual revenue of approximately $64.8 million, or 6.7 percent. The filing was based on a historic test year ending June 2014, adjusted for known and measurable changes, a return on equity (ROE) of 10.25 percent, an electric rate base of approximately $1.6 billion and an equity ratio of 53.97 percent. In March 2015, SPS revised its requested increase to $58.9 million based on updated information.

As part of its request, SPS is seeking a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014.

The following table summarizes the net request:

(Millions of Dollars)	Request
Investment for capital expenditures — post-test year adjustments	$	23.7
Depreciation expense	13.9
Wholesale load reductions	12.0
Purchased power capacity costs	3.2
Other, net	6.1
Total	$	58.9

In April 2015, a revised procedural schedule was established. The next steps are expected to be as follows:

• Intervenor Direct Testimony — May 15, 2015;

• Staff Direct Testimony — May 22, 2015;

• Staff and Intervenor Cross-Rebuttal Testimony — June 8, 2015;

• Rebuttal Testimony — June 10, 2015; and

• Evidentiary Hearing — June 24, 2015.

The parties have agreed the rates will be effective June 11, 2015. A PUCT decision is anticipated in the second half of 2015.

Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Wholesale Rate Complaints— In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, filed a rate complaint alleging that the base ROE included in the SPS production formula rate for Golden Spread of 10.25 percent, and the SPS transmission base formula rate ROE of 10.77 percent, are unjust and unreasonable. In July 2013, Golden Spread filed a second complaint, again asking that the base ROE in the SPS production formula rate for Golden Spread and transmission formula rates be reduced to 9.15 and 9.65 percent, respectively. In June 2014, the FERC issued orders consolidating the Golden Spread ROE complaints and setting the complaints for settlement judge or hearing procedures.

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The FERC established effective dates for the refunds as April 20, 2012 (first refund period) and July 19, 2013 (second refund period). Settlement judge procedures were unsuccessful and the complaints were set for hearings. In the first quarter of 2015, Golden Spread, SPS and FERC staff filed their initial testimonies recommending the following ROEs:

	Refund Period	Production ROE		Transmission ROE (a)
Golden Spread	1	8.78	%	9.28	%
	2	8.51		9.01
SPS	1	10.25		10.39
	2	10.25		11.20
FERC Staff	1	8.97		9.47
	2	8.64		9.14

^(a)  Includes a Southwest Power Pool, Inc. (SPP) Regional Transmission Organization (RTO) membership adder up to 50 basis points.

Hearings are scheduled for July 2015. An initial administrative law judge (ALJ) decision is expected to be issued by Nov. 25, 2015, and a final FERC order to be issued no earlier than 2016.

A third rate complaint was filed in October 2014 by Golden Spread, along with certain New Mexico cooperatives and the West Texas Municipal Power Agency, requesting that the ROE in the SPS production formula rates for Golden Spread and the New Mexico cooperatives and SPS transmission formula rate, which includes an SPP RTO membership adder up to 50 basis points, be reduced to 8.61 percent and 9.11 percent, respectively. The complainants requested a refund effective date of Oct. 20, 2014. In January 2015, the FERC issued an order setting the third complaint for hearing procedures and granting the complainants’ requested refund effective date. A hearing is scheduled for October 2015, with an ALJ initial decision expected in January 2016, and a final FERC order following later in 2016.

SPS recorded a current liability representing the current best estimate of a refund obligation associated with potential ROE adjustments as of March 31, 2015, and is reducing transmission and production revenues, net of expense, between $4 million and $6 million annually.

2004 FERC Complaint Case Orders—In August 2013, the FERC issued an order related to a 2004 complaint case brought by Golden Spread and Public Service Company of New Mexico (PNM) and an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS.

The original complaint included two key components: 1) PNM’s claim regarding inappropriate allocation of fuel costs and 2) a base rate complaint, including the appropriate demand-related cost allocator. The FERC previously determined that the allocation of fuel costs and the demand-related cost allocator utilized by SPS was appropriate.

In the August 2013 Orders, the FERC clarified its previous ruling on the allocation of fuel costs and reaffirmed that the refunds in question should only apply to firm requirements customers and not PNM’s contractual load. The FERC also reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3 coincident peak (CP) rather than a 12 CP system.

In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling. In October 2013, the FERC issued orders further considering the requests for rehearing, which are currently pending. As of Dec. 31, 2014, SPS had accrued $50.4 million related to the August 2013 Orders and an additional $1.8 million of principal and interest was accrued during 2015.

2015 Formula Rate Change Filing—In January 2015, SPS filed to revise the production formula rates for six of its wholesale customers, including Golden Spread, effective Feb. 1, 2015. The filing proposes several modifications, including a reduction in wholesale depreciation rates and the use of a 12 CP demand-related cost allocator for all wholesale customers. On March 31, 2015, the FERC accepted this filing, effective July 1, 2015, subject to refund and settlement judge or hearing procedures. The parties are engaged in settlement judge procedures.

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6. Commitments and Contingencies

Except to the extent noted below and in Note 5, Notes 10 and 11 to the financial statements in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to SPS’ financial position.

Purchased Power Agreements (PPAs)

Under certain PPAs, SPS purchases power from independent power producing entities that own natural gas fueled power plants for which SPS is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.

SPS had approximately 827 megawatts (MW) of capacity under long-term PPAs as of March 31, 2015 and Dec. 31, 2014, with entities that have been determined to be variable interest entities. SPS has concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2033.

Environmental Contingencies

Environmental Requirements

Water and Waste

Coal Ash Regulation —SPS’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment, and disposal of solid waste.  On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule regulating the management and disposal of coal combustion byproducts (coal ash) as a nonhazardous waste.  SPS’s costs to manage and dispose of coal ash will not significantly increase under the new rule.

Air

Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO₂) and nitrous oxide (NOx) from utilities in the eastern half of the United States, including Texas, using an emissions trading program.

In August 2012, the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act (CAA) and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that will now need to be considered on remand. An opinion is expected late summer 2015. In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA will administer the CSAPR in 2015.

Multiple changes to the SPS system since 2011 will substantially reduce estimated costs of complying with the CSAPR. These include the addition of 700 MW of wind power, the construction of Jones Units 3 and 4, reduced wholesale load, new PPAs, installation of NOx combustion controls on Tolk Units 1 and 2 and completion of certain transmission projects. As a result, SPS estimates compliance with the CSAPR in 2015 will cost approximately $7 million. CSAPR compliance in 2015 is not expected to have a material impact on the results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze state implementation plan (SIP), Texas identified the SPS facilities that will have to reduce SO₂, NOx and PM emissions under BART and set emissions limits for those facilities.

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Harrington Units 1 and 2 are potentially subject to BART. Texas developed a SIP that finds the CAIR equal to BART for electric generating units (EGUs). As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. In December 2014, the EPA proposed to approve the BART portion of the SIP, with the exception that the EPA would substitute CSAPR compliance for Texas’ reliance on CAIR. The EPA currently plans to issue its final rule in August 2015.

In May 2014, the EPA issued a request for information under the CAA related to SO₂ control equipment at Tolk Units 1 and 2. In December 2014, the EPA proposed to disapprove the reasonable progress portions of the SIP and instead adopt a Federal Implementation Plan. For SPS, the EPA proposed to require dry scrubbers on both Tolk units to reduce SO₂ emissions to help achieve reasonable progress goals the EPA would establish for Texas and Oklahoma national parks and wilderness areas. As proposed, the dry scrubbers would need to be installed and operating within five years of the EPA’s final action, currently expected in August 2015. SPS filed comments in April 2015, opposing the proposal.Whether dry scrubbers are required is dependent on the EPA’s final decision. If required, they would cost approximately $600 million, with an annual operating cost of approximately $10.4 million.

Legal Contingencies

SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Employment, Tort and Commercial Litigation

Exelon Wind (formerly John Deere Wind) Complaint—Several lawsuits in Texas state and federal courts and regulatory proceedings have arisen out of a dispute concerning SPS’ payments for energy and capacity produced from the Exelon Wind subsidiaries’ projects. There are two main areas of dispute. First, Exelon Wind claims that it established legally enforceable obligations (LEOs) for each of its 12 wind facilities in 2005 through 2008 that require SPS to buy power based on SPS’ forecasted avoided cost as determined in 2005 through 2008. Although SPS has refused to accept Exelon Wind’s LEOs, SPS accepts that it must take energy from Exelon Wind under SPS’ PUCT-approved Qualifying Facilities (QF) Tariff. Second, Exelon Wind has raised various challenges to SPS’ PUCT-approved QF Tariff, which became effective in August 2010. On Jan.16, 2015, Exelon Wind filed motions to dismiss or notices of non-suits for its state and federal lawsuits regarding the QF tariff, and for its state and federal lawsuits and regulatory proceedings regarding the LEOs. Later in January, the PUCT and state and federal courts issued orders dismissing the cases. On April 28, 2015, Exelon Wind filed a notice of withdrawal of its complaint regarding the LEOs, which will become effective on May 13, 2015. The only remaining proceeding is pending before the FERC, and involves the QF Tariff.

SPS believes the likelihood of loss in these proceedings is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms. No accrual has been recorded for this matter.

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7. Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for SPS were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			16
Average amount outstanding	2			9
Maximum amount outstanding	31			100
Weighted average interest rate, computed on a daily basis	0.56		%	0.22		%
Weighted average interest rate at period end	N/A			0.45

Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for SPS was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	400		$	400
Amount outstanding at period end	123			37
Average amount outstanding	103			83
Maximum amount outstanding	144			241
Weighted average interest rate, computed on a daily basis	0.44		%	0.26		%
Weighted average interest rate at period end	0.56			0.47

Letters of Credit — SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At March 31, 2015 and Dec. 31, 2014, there were $30 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At March 31, 2015, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	153	$	247

^(a)  This credit facility expires in October 2019.

^(b)  Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the credit facility outstanding at March 31, 2015 and Dec. 31, 2014.

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8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents— The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Interest rate derivatives— The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by SPS include transmission congestion instruments purchased from the SPP, generally referred to as financial transmission rights (FTRs). FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model - including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are expected to be recovered through fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of SPS, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the financial statements of SPS.

Derivative Instruments Fair Value Measurements

SPS enters into derivative instruments, including forward contracts, for trading purposes and to manage risk in connection with changes in interest rates and electric utility commodity prices.

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Interest Rate Derivatives — SPS may enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At March 31, 2015, accumulated other comprehensive losses related to interest rate derivatives included $0.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Commodity Derivatives — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products and FTRs.

The following table details the gross notional amounts of commodity FTRs at March 31, 2015 and Dec. 31, 2014:

(Amounts in Thousands) (a)	March 31, 2015	Dec. 31, 2014
Megawatt hours of electricity	2,954	6,930

^(a)  Amounts are not reflective of net positions in the underlying commodities.

Impact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for the three months ended March 31, 2015 and 2014.

During the three months ended March 31, 2015 and 2014, changes in the fair value of FTRs resulting in pre-tax net losses of $0.8 million and $1.4 million, respectively, were recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement losses of $0.1 million were recognized for the three months ended March 31, 2015, recorded to electric fuel and purchased power. For the three months ended March 31, 2014, FTR settlement gains of $2.8 million were recognized and recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

SPS had no derivative instruments designated as fair value hedges during the three months ended March 31, 2015 and 2014. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Consideration of Credit Risk and Concentrations — SPS continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of SPS’ own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the balance sheets.

SPS employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

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SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At March 31, 2015, one of SPS’ eight most significant counterparties for these activities, comprising $7.8 million or 9 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Six of the eight most significant counterparties, comprising $44.7 million or 50 percent of this credit exposure, were not rated by these agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $1.0 million or 1 percent of this credit exposure, had credit quality less than investment grade, based on SPS' internal analysis. All eight of these significant counterparties are RTOs, municipal or cooperative electric entities or other utilities.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2015:

	March 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	10,338	$	10,338	$	(3,880	)	$	6,458
Total current derivative assets	$	—	$	—	$	10,338	$	10,338	$	(3,880	)	6,458
PPAs (a)												7,892
Current derivative instruments												$	14,350
Noncurrent derivative assets
PPAs (a)												$	31,191
Noncurrent derivative instruments												$	31,191
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	3,881	$	3,881	$	(3,881	)	$	—
Total current derivative liabilities	$	—	$	—	$	3,881	$	3,881	$	(3,881	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	29,752
Noncurrent derivative instruments												$	29,752

^(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b) SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2015. At March 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2014:

	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	25,774	$	25,774	$	(9,890	)	$	15,884
Total current derivative assets	$	—	$	—	$	25,774	$	25,774	$	(9,890	)	15,884
PPAs (a)												7,892
Current derivative instruments												$	23,776
Noncurrent derivative assets
PPAs (a)												$	33,164
Noncurrent derivative instruments												$	33,164
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	9,890	$	9,890	$	(9,890	)	$	—
Total current derivative liabilities	$	—	$	—	$	9,890	$	9,890	$	(9,890	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	30,643
Noncurrent derivative instruments												$	30,643

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2014. At Dec. 31, 2014, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents the changes in Level 3 commodity derivatives for the three months ended March 31, 2015 and 2014:

	Three Months Ended March 31
(Thousands of Dollars)	2015			2014
Balance at Jan. 1	$	15,884		$	9,933
Purchases	4,928			1,056
Settlements	(8,379		)	(1,101		)
Net transactions recorded during the period:
Losses recognized as regulatory assets and liabilities	(5,976		)	(4,097		)
Balance at March 31	$	6,457		$	5,791

SPS recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three months ended March 31, 2015 and 2014.

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Fair Value of Long-Term Debt

As of March 31, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,349,774	$	1,596,427	$	1,349,691	$	1,572,414

The fair value of SPS’ long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of March 31, 2015 and Dec. 31, 2014, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

9. Other (Expense) Income, Net

Other (expense) income, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2015			2014
Interest income	$	32		$	187
Other nonoperating income	45			—
Insurance policy expense	(133		)	(144		)
Other nonoperating expense	—			(2		)
Other (expense) income, net	$	(56	)	$	41

10. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended March 31
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,752		$	2,296		$	239		$	312
Interest cost	5,046			5,111			436			643
Expected return on plan assets	(7,153		)	(6,545		)	(635		)	(812		)
Amortization of prior service cost (credit)	10			14			(100		)	(100		)
Amortization of net loss (gain)	3,772			3,332			(160		)	(80		)
Net periodic benefit cost (credit)	4,427			4,208			(220		)	(37		)
Credits recognized due to the effects of regulation	713			707			—			—
Net benefit cost (credit) recognized for financial reporting	$	5,140		$	4,915		$	(220	)	$	(37	)

In January 2015, contributions of $90.0 million were made across four of Xcel Energy’s pension plans, of which $11.6 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2015.

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11. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended March 31, 2015			Three Months Ended March 31, 2014
Accumulated other comprehensive loss at Jan. 1	$	(989	)	$	(1,161	)
Losses reclassified from net accumulated other comprehensive loss	42			43
Net current period other comprehensive income	42			43
Accumulated other comprehensive loss at March 31	$	(947	)	$	(1,118	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2015				Three Months Ended March 31, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	66		(a)	$	67		(a)
Total, pre-tax	66				67
Tax benefit	(24		)		(24		)
Total amounts reclassified, net of tax	$	42			$	43

^(a)  Included in interest charges.

Item 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for SPS is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on SPS’ financial condition, results of operations, and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited financial statements and the related notes to the financial statements.  Due to the seasonality of SPS’ electric sales, such interim results are not necessarily an appropriate base from which to project annual results.

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slowdown in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where SPS has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric market; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; and the other risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of SPS’ Form 10-K for the year ended Dec. 31, 2014, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended March 31, 2015.

Results of Operations

SPS’ net income was approximately $20.2 million for the three months endedMarch 31, 2015, compared with net income of approximately $18.7 million for the same period in 2014. The increase was primarily due to the positive impact of higher electric rates in Texas and New Mexico, partially offset by increased depreciation and operating and maintenance (O&M) expenses.

Electric Revenues and Margin

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. The design of fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses and, therefore, changes in fuel or purchased power costs can impact earnings. The following tables detail the electric revenues and margin:

	Three Months Ended March 31
(Millions of Dollars)	2015			2014
Electric revenues	$	424		$	448
Electric fuel and purchased power	(246		)	(289		)
Electric margin	$	178		$	159

The following tables summarize the components of the changes in electric revenues and electric margin for the three months ended March 31:

Electric Revenues

(Millions of Dollars)	2015 vs. 2014
Fuel and purchased power cost recovery	$	(56	)
Estimated impact of weather	(3		)
Retail rate increases (Texas and New Mexico)	13
Trading	10
Transmission revenue	5
Demand revenue	3
Non-fuel riders	1
Other, net	3
Total decrease in electric revenues	$	(24	)

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Electric Margin

(Millions of Dollars)	2015 vs. 2014
Retail rate increases (Texas and New Mexico)	$	13
Transmission revenue, net of costs	7
Demand revenue	3
Non-fuel riders	1
Texas wind renewable energy credits	(3		)
Estimated impact of weather	(3		)
Other, net	1
Total increase in electric margin	$	19

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses increased $4.5 million, or 6.5 percent, for the three months ended March 31, 2015 compared with the same period in 2014. The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2015 vs. 2014
Plant generation costs	$	2
Transmission cost increases	1
Employee benefits	1
Other, net	1
Total increase in O&M expenses	$	5

Depreciation and Amortization — Depreciation and amortization increased $5.2 million, or 17.1 percent, for the three months ended March 31, 2015 compared with the same period in 2014. The increase is primarily due to normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $1.3 million, or 9.7 percent, for the three months ended March 31, 2015 compared with the same period in 2014. The increase is primarily due to an increase in property and general taxes.

Allowance for Funds Used During Construction (AFUDC) —AFUDC decreased $3.0 million for the three months ended March 31, 2015 compared with the same period in 2014. The decrease is primarily due to the decrease of transmission facilities construction.

Interest Charges — Interest charges increased $1.6 million, or 8.3 percent, for the three months ended March 31, 2015 compared with the same period in 2014. The increase is primarily due to higher long-term debt levels, partially offset by lower interest rates.

Income Taxes — Income tax expense increased $1.0 million for the three months ended March 31, 2015 compared with the same period in 2014. The increase in income tax expense is primarily due to higher pre-tax earnings and decreased permanent plant-related adjustments in 2015. The ETR was 35.9 percent for the three months ended March 31, 2015, compared with 35.6 percent for the same period in 2014.

Public Utility Regulation

Transmission Notifications to Construct (NTC) — As a member of SPP, SPS accepts NTCs for electric transmission line and substation projects to be built within the SPP footprint. SPS has accepted NTCs for projects with an estimated capital cost of approximately $1.9 billion and will continue to review new NTCs for acceptance as they are issued. These projects generally span several years to plan, site, procure and develop. The New Mexico Public Regulatory Commission (NMPRC) and the PUCT must approve the siting and routing of any SPP identified transmission line NTC projects that require permitting approval. Projects identified through SPP NTCs may have costs allocated to other SPP members in accordance with the SPP Open Access Transmission Tariff (OATT). Costs allocated to SPS are permissible for recovery through the NMPRC, the PUCT and the FERC processes.

Chaves County, N.M. Solar Contracts — In March 2015, SPS entered into two purchased energy contracts with NextEra Resources for the purchase of solar generated electricity from two 70 MW projects to be constructed in Chaves County, N.M.. The two 25-year contracts are subject to regulatory approval and they are now pending review and approval by the NMPRC. The purchased energy will be recovered from customers through SPS’ fuel and purchased energy cost recovery mechanisms.

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Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, asset transactions and mergers, accounting practices and certain other activities of SPS, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014. In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

FERC Order, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. In October 2014, the FERC upheld the determination of the long-term growth rate to be used in its new ROE methodology. In March 2015, the FERC issued an order on rehearing upholding use of the new ROE methodology.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of March 31, 2015, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in SPS’ internal control over financial reporting has occurred during SPS’ most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, SPS’ internal control over financial reporting.

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Additional Information

See Note 6 to the financial statements for further discussion of legal claims and environmental proceedings.  See Note 5 to the financial statements for discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

SPS’ risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2014, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Item 4—MINE SAFETY DISCLOSURES

None.

22

Item 5—OTHER INFORMATION

None.

Item 6 — EXHIBITS

*  Indicates incorporation by reference

3.01*	Amended and Restated Articles of Incorporation of SPS dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
3.02*	By-Laws of SPS as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03789)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from SPS’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Statements of Income, (ii) the Statements of Comprehensive Income (iii) the Statements of Cash Flows, (iv) the Balance Sheets, (v) Notes to Financial Statements, and (vi) document and entity information.

23

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Southwestern Public Service Company
May 4, 2015	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)
		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

24

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Ben Fowke, certify that:

1. I have reviewed this report on Form 10-Q of Southwestern Public Service Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 4, 2015

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Teresa S. Madden, certify that:

1. I have reviewed this report on Form 10-Q of Southwestern Public Service Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting

Date: May 4, 2015

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Southwestern Public Service Company (SPS) on Form 10-Q for the quarter ended March 31, 2015, as filed with the SEC on the date hereof (Form 10-Q), each of the undersigned officers of SPS certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of SPS as of the dates and for the periods expressed in the Form 10-Q.

Date: May 4, 2015

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to SPS and will be retained by SPS and furnished to the SEC or its staff upon request.

1

EX-99.01

Exhibit 99.01

SPS Cautionary Factors

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement.  Forward-looking statements are made in written documents and oral presentations of SPS, Xcel Energy Inc. or any of its other subsidiaries.  These statements are based on management’s beliefs as well as assumptions and information currently available to management.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause SPS’ actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

• Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

• The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of past or future terrorist attacks;

• Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where SPS has a financial interest;

• Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

• Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the FERC and similar entities with regulatory oversight;

• Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, SPS, Xcel Energy Inc. or any of its other subsidiaries; or security ratings;

• Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; cyber incidents; or electric transmission or natural gas pipeline constraints;

• Employee workforce factors, including loss or retirement of key executives, collective-bargaining agreements with union employees, or work stoppages;

• Increased competition in the utility industry or additional competition in the markets served by SPS, Xcel Energy Inc. and its other subsidiaries;

• State and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric market; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

• Environmental laws and regulations, including legislation and regulations relating to climate change, and the associated cost of compliance;

• Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

• Social attitudes regarding the utility and power industries;

• Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

• Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

• Risks associated with implementation of new technologies; and

• Other business or investment considerations that may be disclosed from time to time in SEC filings, including “Risk Factors” in Item 1A of SPS’ Form 10-K for the year ended Dec. 31, 2014, or in other publicly disseminated written documents.

 SPS undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  The foregoing review of factors should not be construed as exhaustive.

1

XML

Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Amount outstanding at period end	123,000	$ 37,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	30,000
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

XML

Other Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ (989)
Accumulated other comprehensive loss at end of period	(947)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	(31,585)		(29,103)
Tax benefit	11,338		10,368
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(989)		(1,161)
Losses reclassified from net accumulated other comprehensive loss	42		43
Net current period other comprehensive income	42		43
Accumulated other comprehensive loss at end of period	(947)		(1,118)
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	66		67
Tax benefit	(24)		(24)
Total, net of tax	42		43
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	$ 66	[1]	$ 67	[1]

[1] Included in interest charges.

XML

Other Income (Expense), Net (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Other Income and Expenses [Abstract]
Interest income	$ 32	$ 187
Other nonoperating income	45	0
Insurance policy expense	(133)	(144)
Other Nonoperating Expense	0	(2)
Other (expense) income, net	$ (56)	$ 41

XML

Income Taxes (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Sep. 30, 2012	Dec. 31, 2014
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit - Permanent tax positions	$ 1,500,000		$ 1,500,000
Unrecognized tax benefit - Temporary tax positions	12,300,000		11,700,000
Total unrecognized tax benefit	13,800,000		13,200,000
NOL and tax credit carryforwards	(5,500,000)		(4,800,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	(2,000,000)
Amounts accrued for penalties related to unrecognized tax benefits	0
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Earliest year subject to examination	2009
Year(s) under examination		2010 and 2011
Year of carryback claim under examination		2009
Potential Tax Adjustments	$ 12,000,000
State Jurisdiction (Texas)
Tax Audits [Abstract]
Earliest year subject to examination	2009

XML

Fair Value of Financial Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity FTRs

The following table details the gross notional amounts of commodity FTRs at March 31, 2015 and Dec. 31, 2014:

(Amounts in Thousands) (a)	March 31, 2015	Dec. 31, 2014
Megawatt hours of electricity	2,954	6,930

^(a)  Amounts are not reflective of net positions in the underlying commodities.

Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2015:

	March 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	10,338	$	10,338	$	(3,880	)	$	6,458
Total current derivative assets	$	—	$	—	$	10,338	$	10,338	$	(3,880	)	6,458
PPAs (a)												7,892
Current derivative instruments												$	14,350
Noncurrent derivative assets
PPAs (a)												$	31,191
Noncurrent derivative instruments												$	31,191
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	3,881	$	3,881	$	(3,881	)	$	—
Total current derivative liabilities	$	—	$	—	$	3,881	$	3,881	$	(3,881	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	29,752
Noncurrent derivative instruments												$	29,752

^(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b) SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2015. At March 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2014:

	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	25,774	$	25,774	$	(9,890	)	$	15,884
Total current derivative assets	$	—	$	—	$	25,774	$	25,774	$	(9,890	)	15,884
PPAs (a)												7,892
Current derivative instruments												$	23,776
Noncurrent derivative assets
PPAs (a)												$	33,164
Noncurrent derivative instruments												$	33,164
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	9,890	$	9,890	$	(9,890	)	$	—
Total current derivative liabilities	$	—	$	—	$	9,890	$	9,890	$	(9,890	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	30,643
Noncurrent derivative instruments												$	30,643

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2014. At Dec. 31, 2014, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

Changes in Level 3 Commodity Derivatives

The following table presents the changes in Level 3 commodity derivatives for the three months ended March 31, 2015 and 2014:

	Three Months Ended March 31
(Thousands of Dollars)	2015			2014
Balance at Jan. 1	$	15,884		$	9,933
Purchases	4,928			1,056
Settlements	(8,379		)	(1,101		)
Net transactions recorded during the period:
Losses recognized as regulatory assets and liabilities	(5,976		)	(4,097		)
Balance at March 31	$	6,457		$	5,791

Carrying Amount and Fair Value of Long-term Debt

As of March 31, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,349,774	$	1,596,427	$	1,349,691	$	1,572,414

XML

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0	0
Cash Flow Hedges | Interest Rate Contract
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax losses reclassified into income during the period from accumulated other comprehensive loss	(100,000)	(100,000)
Other Derivative Instruments | Electric Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value losses recognized during the period in regulatory assets and liabilities	(800,000)	(1,400,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	$ 100,000	$ (2,800,000)

XML

Commitments and Contingencies, Legal Contingencies (Details) (SPS [Member], Exelon Wind Complaint, USD $)	Mar. 31, 2015 Site Dispute
SPS [Member] | Exelon Wind Complaint
Legal Contingencies [Abstract]
Number of main areas of dispute	2
Number of wind facilities	12
Accrual for legal contingency	$ 0

XML

Benefit Plans and Other Postretirement Benefits (Details) (USD $)	1 Months Ended	3 Months Ended
	Jan. 31, 2015	Mar. 31, 2015	Mar. 31, 2014
Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 2,752,000	$ 2,296,000
Interest cost		5,046,000	5,111,000
Expected return on plan assets		(7,153,000)	(6,545,000)
Amortization of prior service cost (credit)		10,000	14,000
Amortization of net loss (gain)		3,772,000	3,332,000
Net periodic benefit cost (credit)		4,427,000	4,208,000
Credits recognized (costs not recognized) due to the effects of regulation		713,000	707,000
Net benefit cost (credit) recognized for financial reporting		5,140,000	4,915,000
Total contributions to the pension plans during the period	11,600,000
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		239,000	312,000
Interest cost		436,000	643,000
Expected return on plan assets		(635,000)	(812,000)
Amortization of prior service cost (credit)		(100,000)	(100,000)
Amortization of net loss (gain)		(160,000)	(80,000)
Net periodic benefit cost (credit)		(220,000)	(37,000)
Credits recognized (costs not recognized) due to the effects of regulation		0	0
Net benefit cost (credit) recognized for financial reporting		(220,000)	(37,000)
Xcel Energy Inc. | Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Total contributions to the pension plans during the period	$ 90,000,000
Number of Xcel Energy's pension plans to which contributions were made	4

XML

Management's Opinion

3 Months Ended

Mar. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Management's Opinion

In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of SPS as of March 31, 2015, and Dec. 31, 2014; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2015 and 2014; and its cash flows for the three months endedMarch 31, 2015 and 2014. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2015 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2014 balance sheet information has been derived from the audited 2014 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014. These notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the financial statements and notes thereto included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014, filed with the SEC on Feb. 23, 2015. Due to the seasonality of SPS’ electric sales, interim results are not necessarily an appropriate base from which to project annual results.

XML

Fair Value of Financial Assets and Liabilities, Fair Value Measurements (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset	$ 0		$ 0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0		0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	14,350,000		23,776,000
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	31,191,000		33,164,000
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,565,000		3,565,000
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	29,752,000		30,643,000
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6,458,000		15,884,000
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6,458,000		15,884,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	10,338,000		25,774,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	10,338,000		25,774,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,881,000		9,890,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,881,000		9,890,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	10,338,000		25,774,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	10,338,000		25,774,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,881,000		9,890,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,881,000		9,890,000
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(3,880,000)	[1]	(9,890,000)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(3,880,000)	[1]	(9,890,000)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(3,881,000)	[1]	(9,890,000)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(3,881,000)	[1]	(9,890,000)	[2]
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	7,892,000	[3]	7,892,000	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	31,191,000	[3]	33,164,000	[4]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,565,000	[3]	3,565,000	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 29,752,000	[3]	$ 30,643,000	[4]

[1] SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2015. At March 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

[2] SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2014. At Dec. 31, 2014, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

[3] In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

[4] In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities

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Accounting Pronouncements Accounting Pronouncements (Details)	3 Months Ended
	Mar. 31, 2015
Revenue Recognition [Abstract]
Exposure period for public comment (in days)	30 days

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Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2015

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Loss, Net of Tax

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended March 31, 2015			Three Months Ended March 31, 2014
Accumulated other comprehensive loss at Jan. 1	$	(989	)	$	(1,161	)
Losses reclassified from net accumulated other comprehensive loss	42			43
Net current period other comprehensive income	42			43
Accumulated other comprehensive loss at March 31	$	(947	)	$	(1,118	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2015				Three Months Ended March 31, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	66		(a)	$	67		(a)
Total, pre-tax	66				67
Tax benefit	(24		)		(24		)
Total amounts reclassified, net of tax	$	42			$	43

^(a)  Included in interest charges.

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Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Commodity Contract, USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Commodity Contract
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period	$ 15,884,000	$ 9,933,000
Purchases	4,928,000	1,056,000
Settlements	(8,379,000)	(1,101,000)
Losses recognized as regulatory assets and liabilities	(5,976,000)	(4,097,000)
Balance at end of period	6,457,000	5,791,000
Transfers into Level 3	0	0
Transfers out of Level 3	$ 0	$ 0

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Selected Balance Sheet Data (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$ 84,817	$ 77,465
Less allowance for bad debts	(6,107)	(5,839)
Accounts receivable, net	$ 78,710	$ 71,626

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Public Utilities, Inventory [Line Items]
Inventories	$ 31,749	$ 43,231
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	25,500	24,738
Fuel
Public Utilities, Inventory [Line Items]
Inventories	$ 6,249	$ 18,493

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BALANCE SHEETS (UNAUDITED) (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Capitalization, Long-term Debt and Equity [Abstract]
Common stock, shares authorized (in shares)	200	200
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, shares outstanding (in shares)	100	100

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 5,729,671	$ 5,615,125
Less accumulated depreciation	(1,898,627)	(1,871,984)
Property, plant and equipment, net	3,831,044	3,743,141
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	5,480,750	5,376,606
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 248,921	$ 238,519

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Borrowings and Other Financing Instruments, Credit Facility (Details) (Credit Facility, USD $)	Mar. 31, 2015
Credit Facility
Line of Credit Facility [Line Items]
Credit Facility	$ 400,000,000	[1]
Drawn	153,000,000	[2]
Available	247,000,000
Direct advances on the credit facility outstanding	$ 0

[1] This credit facility expires in October 2019.

[2] Includes outstanding commercial paper and letters of credit.

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STATEMENTS OF INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Income Statement [Abstract]
Operating revenues	$ 423,829	$ 448,400
Operating expenses
Electric fuel and purchased power	245,799	289,204
Operating and maintenance expenses	73,897	69,398
Demand side management program expenses	3,669	3,064
Depreciation and amortization	35,739	30,512
Taxes (other than income taxes)	14,966	13,646
Total operating expenses	374,070	405,824
Operating income	49,759	42,576
Other (expense) income, net	(56)	41
Allowance for funds used during construction — equity	1,705	3,640
Interest charges and financing costs
Interest charges — includes other financing costs of $774 and $730, respectively	20,884	19,281
Allowance for funds used during construction — debt	(1,061)	(2,127)
Total interest charges and financing costs	19,823	17,154
Income before income taxes	31,585	29,103
Income taxes	11,338	10,368
Net income	$ 20,247	$ 18,735

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,349,774	$ 1,349,691
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,596,427	$ 1,572,414

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STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Operating activities
Net income	$ 20,247	$ 18,735
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	36,310	31,059
Demand side management program amortization	418	418
Deferred income taxes	3,617	22,166
Amortization of investment tax credits	(85)	(85)
Allowance for equity funds used during construction	(1,705)	(3,640)
Net derivative losses	66	66
Changes in operating assets and liabilities:
Accounts receivable	(12,719)	12,526
Accrued unbilled revenues	26,906	(2,413)
Inventories	11,482	5,131
Prepayments and other	(12,485)	(15,455)
Accounts payable	(21,160)	9,454
Net regulatory assets and liabilities	29,566	(16,994)
Other current liabilities	12,521	3,908
Pension and other employee benefit obligations	(10,954)	(3,513)
Change in other noncurrent assets	301	2,951
Change in other noncurrent liabilities	378	1,758
Net cash provided by operating activities	82,704	66,072
Investing activities
Utility capital/construction expenditures	(126,622)	(137,637)
Allowance for equity funds used during construction	1,705	3,640
Investments in utility money pool arrangement	(9,000)	(10,000)
Repayments from utility money pool arrangement	9,000	10,000
Net cash used in investing activities	(124,917)	(133,997)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	86,000	(15,000)
Borrowings under utility money pool arrangement	41,000	231,000
Repayments under utility money pool arrangement	(57,000)	(169,000)
Capital contributions from parent	0	40,000
Dividends paid to parent	(27,828)	(18,082)
Net cash provided by financing activities	42,172	68,918
Net change in cash and cash equivalents	(41)	993
Cash and cash equivalents at beginning of period	596	1,011
Cash and cash equivalents at end of period	555	2,004
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(8,870)	(7,570)
Cash paid for income taxes, net	(19,004)	(2,522)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 28,426	$ 30,938

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Commitments and Contingencies, Purchased Power Agreements (Details) (Independent Power Producing Entities)	3 Months Ended
	Mar. 31, 2015 MW	Dec. 31, 2014 MW
Independent Power Producing Entities
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	827	827
Purchase Power Agreement Duration, Maximum (year)	2033

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2015

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	March 31, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	1.5	$	1.5
Unrecognized tax benefit — Temporary tax positions	12.3		11.7
Total unrecognized tax benefit	$	13.8	$	13.2

Tax Benefits Associated with NOL and Tax Credit Carryforwards

The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)	March 31, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(5.5	)	$	(4.8	)

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Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended
	Dec. 31, 2014	Mar. 31, 2015 MW	Apr. 30, 2014 Issue
Cross-State Air Pollution Rule
Environmental Requirements [Abstract]
Number of issues on which the D.C. Circuit overturned the CSAPR			2
Generating capacity (in MW)		700
Regional Haze Rules [Member]
Environmental Requirements [Abstract]
Number of years to comply with proposed regulation	5 years
Capital Commitments | Cross-State Air Pollution Rule
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation		7
Capital Commitments | Regional Haze Rules [Member]
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation		600
Estimated annual operating cost to comply with proposed regulation		10.4

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Borrowings and Other Financing Instruments (Tables)

3 Months Ended

Mar. 31, 2015

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At March 31, 2015, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	153	$	247

^(a)  This credit facility expires in October 2019.

^(b)  Includes outstanding commercial paper and letters of credit.

Money Pool

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Money pool borrowings for SPS were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			16
Average amount outstanding	2			9
Maximum amount outstanding	31			100
Weighted average interest rate, computed on a daily basis	0.56		%	0.22		%
Weighted average interest rate at period end	N/A			0.45

Commercial Paper

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Commercial paper outstanding for SPS was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	400		$	400
Amount outstanding at period end	123			37
Average amount outstanding	103			83
Maximum amount outstanding	144			241
Weighted average interest rate, computed on a daily basis	0.44		%	0.26		%
Weighted average interest rate at period end	0.56			0.47

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BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 555	$ 596
Accounts receivable, net	78,710	71,626
Accounts receivable from affiliates	7,618	1,983
Accrued unbilled revenues	102,381	129,287
Inventories	31,749	43,231
Regulatory assets	48,911	52,006
Derivative instruments	14,350	23,776
Deferred income taxes	79,013	51,854
Prepayments and other	45,554	31,476
Total current assets	408,841	405,835
Property, plant and equipment, net	3,831,044	3,743,141
Other assets
Regulatory assets	314,557	323,305
Derivative instruments	31,191	33,164
Other	15,438	15,859
Total other assets	361,186	372,328
Total assets	4,601,071	4,521,304
Current liabilities
Short-term debt	123,000	37,000
Borrowings under utility money pool arrangement	0	16,000
Accounts payable	140,907	160,762
Accounts payable to affiliates	15,343	19,790
Regulatory liabilities	104,009	87,723
Taxes accrued	19,848	27,208
Accrued interest	27,327	17,057
Dividends payable	25,339	27,828
Derivative instruments	3,565	3,565
Other	88,724	80,211
Total current liabilities	548,062	477,144
Deferred credits and other liabilities
Deferred income taxes	878,653	849,145
Regulatory liabilities	110,867	115,188
Asset retirement obligations	26,369	26,031
Derivative instruments	29,752	30,643
Pension and employee benefit obligations	92,647	103,670
Other	9,553	9,320
Total deferred credits and other liabilities	1,147,841	1,133,997
Commitments and contingencies
Capitalization
Long-term debt	1,349,774	1,349,691
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at March 31, 2015 and Dec. 31, 2014, respectively	0	0
Additional paid in capital	1,165,435	1,165,463
Retained earnings	390,906	395,998
Accumulated other comprehensive loss	(947)	(989)
Total common stockholder's equity	1,555,394	1,560,472
Total liabilities and equity	$ 4,601,071	$ 4,521,304

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STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Interest charges and financing costs
Other financing costs	$ 774	$ 730

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Fair Value of Financial Assets and Liabilities

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents— The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Interest rate derivatives— The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by SPS include transmission congestion instruments purchased from the SPP, generally referred to as financial transmission rights (FTRs). FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model - including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are expected to be recovered through fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of SPS, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the financial statements of SPS.

Derivative Instruments Fair Value Measurements

SPS enters into derivative instruments, including forward contracts, for trading purposes and to manage risk in connection with changes in interest rates and electric utility commodity prices.

Interest Rate Derivatives — SPS may enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At March 31, 2015, accumulated other comprehensive losses related to interest rate derivatives included $0.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Commodity Derivatives — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products and FTRs.

The following table details the gross notional amounts of commodity FTRs at March 31, 2015 and Dec. 31, 2014:

(Amounts in Thousands) (a)	March 31, 2015	Dec. 31, 2014
Megawatt hours of electricity	2,954	6,930

^(a)  Amounts are not reflective of net positions in the underlying commodities.

Impact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for the three months ended March 31, 2015 and 2014.

During the three months ended March 31, 2015 and 2014, changes in the fair value of FTRs resulting in pre-tax net losses of $0.8 million and $1.4 million, respectively, were recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement losses of $0.1 million were recognized for the three months ended March 31, 2015, recorded to electric fuel and purchased power. For the three months ended March 31, 2014, FTR settlement gains of $2.8 million were recognized and recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

SPS had no derivative instruments designated as fair value hedges during the three months ended March 31, 2015 and 2014. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Consideration of Credit Risk and Concentrations — SPS continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of SPS’ own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the balance sheets.

SPS employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At March 31, 2015, one of SPS’ eight most significant counterparties for these activities, comprising $7.8 million or 9 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Six of the eight most significant counterparties, comprising $44.7 million or 50 percent of this credit exposure, were not rated by these agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $1.0 million or 1 percent of this credit exposure, had credit quality less than investment grade, based on SPS' internal analysis. All eight of these significant counterparties are RTOs, municipal or cooperative electric entities or other utilities.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at March 31, 2015:

	March 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	10,338	$	10,338	$	(3,880	)	$	6,458
Total current derivative assets	$	—	$	—	$	10,338	$	10,338	$	(3,880	)	6,458
PPAs (a)												7,892
Current derivative instruments												$	14,350
Noncurrent derivative assets
PPAs (a)												$	31,191
Noncurrent derivative instruments												$	31,191
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	3,881	$	3,881	$	(3,881	)	$	—
Total current derivative liabilities	$	—	$	—	$	3,881	$	3,881	$	(3,881	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	29,752
Noncurrent derivative instruments												$	29,752

^(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b) SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2015. At March 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2014:

	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	25,774	$	25,774	$	(9,890	)	$	15,884
Total current derivative assets	$	—	$	—	$	25,774	$	25,774	$	(9,890	)	15,884
PPAs (a)												7,892
Current derivative instruments												$	23,776
Noncurrent derivative assets
PPAs (a)												$	33,164
Noncurrent derivative instruments												$	33,164
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	9,890	$	9,890	$	(9,890	)	$	—
Total current derivative liabilities	$	—	$	—	$	9,890	$	9,890	$	(9,890	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	30,643
Noncurrent derivative instruments												$	30,643

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2014. At Dec. 31, 2014, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents the changes in Level 3 commodity derivatives for the three months ended March 31, 2015 and 2014:

	Three Months Ended March 31
(Thousands of Dollars)	2015			2014
Balance at Jan. 1	$	15,884		$	9,933
Purchases	4,928			1,056
Settlements	(8,379		)	(1,101		)
Net transactions recorded during the period:
Losses recognized as regulatory assets and liabilities	(5,976		)	(4,097		)
Balance at March 31	$	6,457		$	5,791

SPS recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three months ended March 31, 2015 and 2014.

Fair Value of Long-Term Debt

As of March 31, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,349,774	$	1,596,427	$	1,349,691	$	1,572,414

The fair value of SPS’ long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of March 31, 2015 and Dec. 31, 2014, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

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Document and Entity Information	3 Months Ended
	Mar. 31, 2015	May 04, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	SOUTHWESTERN PUBLIC SERVICE CO
Entity Central Index Key	0000092521
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		100

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Other Income (Expense), Net

3 Months Ended

Mar. 31, 2015

Other Income and Expenses [Abstract]

Other Income (Expense), Net

Other (Expense) Income, Net

Other (expense) income, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2015			2014
Interest income	$	32		$	187
Other nonoperating income	45			—
Insurance policy expense	(133		)	(144		)
Other nonoperating expense	—			(2		)
Other (expense) income, net	$	(56	)	$	41

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STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Comprehensive income:
Net income	$ 20,247	$ 18,735
Derivative instruments:
Reclassification of losses to net income, net of tax of $24 for each of the three months ended March 31, 2015 and 2014, respectively	42	43
Other comprehensive income	42	43
Comprehensive income	$ 20,289	$ 18,778

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Selected Balance Sheet Data

3 Months Ended

Mar. 31, 2015

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	84,817		$	77,465
Less allowance for bad debts	(6,107		)	(5,839		)
	$	78,710		$	71,626

(Thousands of Dollars)	March 31, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	25,500	$	24,738
Fuel	6,249		18,493
	$	31,749	$	43,231

(Thousands of Dollars)	March 31, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	5,480,750		$	5,376,606
Construction work in progress	248,921			238,519
Total property, plant and equipment	5,729,671			5,615,125
Less accumulated depreciation	(1,898,627		)	(1,871,984		)
	$	3,831,044		$	3,743,141

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Accounting Pronouncements

3 Months Ended

Mar. 31, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

Accounting Pronouncements

Recently Issued

Revenue Recognition— In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, is effective for interim and annual reporting periods beginning after Dec. 15, 2016. In April 2015, the FASB tentatively decided to defer the effective date by one year, making the guidance effective for interim and annual reporting periods beginning after Dec. 15, 2017. This tentative decision will be exposed for public input in an upcoming proposed ASU with a 30-day comment period. SPS is currently evaluating the impact of adopting ASU 2014-09 on its financial statements.

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. SPS is currently evaluating the impact of adopting ASU 2015-02 on its financial statements.

Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the balance sheets, SPS does not expect the implementation of ASU 2015-03 to have a material impact on its financial statements.

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Rate Matters (Tables)

3 Months Ended

Mar. 31, 2015

Public Utilities, General Disclosures [Abstract]

SPS' Texas 2015 Electric Rate Case [Table Text Block]

As part of its request, SPS is seeking a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014.

The following table summarizes the net request:

(Millions of Dollars)	Request
Investment for capital expenditures — post-test year adjustments	$	23.7
Depreciation expense	13.9
Wholesale load reductions	12.0
Purchased power capacity costs	3.2
Other, net	6.1
Total	$	58.9

FERC Wholesale Rate Complaints [Table Text Block]

The FERC established effective dates for the refunds as April 20, 2012 (first refund period) and July 19, 2013 (second refund period). Settlement judge procedures were unsuccessful and the complaints were set for hearings. In the first quarter of 2015, Golden Spread, SPS and FERC staff filed their initial testimonies recommending the following ROEs:

	Refund Period	Production ROE		Transmission ROE (a)
Golden Spread	1	8.78	%	9.28	%
	2	8.51		9.01
SPS	1	10.25		10.39
	2	10.25		11.20
FERC Staff	1	8.97		9.47
	2	8.64		9.14

^(a)  Includes a Southwest Power Pool, Inc. (SPP) Regional Transmission Organization (RTO) membership adder up to 50 basis points.

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Benefit Plans and Other Postretirement Benefits

3 Months Ended

Mar. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended March 31
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,752		$	2,296		$	239		$	312
Interest cost	5,046			5,111			436			643
Expected return on plan assets	(7,153		)	(6,545		)	(635		)	(812		)
Amortization of prior service cost (credit)	10			14			(100		)	(100		)
Amortization of net loss (gain)	3,772			3,332			(160		)	(80		)
Net periodic benefit cost (credit)	4,427			4,208			(220		)	(37		)
Credits recognized due to the effects of regulation	713			707			—			—
Net benefit cost (credit) recognized for financial reporting	$	5,140		$	4,915		$	(220	)	$	(37	)

In January 2015, contributions of $90.0 million were made across four of Xcel Energy’s pension plans, of which $11.6 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2015.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Except to the extent noted below and in Note 5, Notes 10 and 11 to the financial statements in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to SPS’ financial position.

Purchased Power Agreements (PPAs)

Under certain PPAs, SPS purchases power from independent power producing entities that own natural gas fueled power plants for which SPS is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.

SPS had approximately 827 megawatts (MW) of capacity under long-term PPAs as of March 31, 2015 and Dec. 31, 2014, with entities that have been determined to be variable interest entities. SPS has concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2033.

Environmental Contingencies

Environmental Requirements

Water and Waste

Coal Ash Regulation —SPS’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment, and disposal of solid waste.  On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule regulating the management and disposal of coal combustion byproducts (coal ash) as a nonhazardous waste.  SPS’s costs to manage and dispose of coal ash will not significantly increase under the new rule.

Air

Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO₂) and nitrous oxide (NOx) from utilities in the eastern half of the United States, including Texas, using an emissions trading program.

In August 2012, the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act (CAA) and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that will now need to be considered on remand. An opinion is expected late summer 2015. In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA will administer the CSAPR in 2015.

Multiple changes to the SPS system since 2011 will substantially reduce estimated costs of complying with the CSAPR. These include the addition of 700 MW of wind power, the construction of Jones Units 3 and 4, reduced wholesale load, new PPAs, installation of NOx combustion controls on Tolk Units 1 and 2 and completion of certain transmission projects. As a result, SPS estimates compliance with the CSAPR in 2015 will cost approximately $7 million. CSAPR compliance in 2015 is not expected to have a material impact on the results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze state implementation plan (SIP), Texas identified the SPS facilities that will have to reduce SO₂, NOx and PM emissions under BART and set emissions limits for those facilities.

Harrington Units 1 and 2 are potentially subject to BART. Texas developed a SIP that finds the CAIR equal to BART for electric generating units (EGUs). As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. In December 2014, the EPA proposed to approve the BART portion of the SIP, with the exception that the EPA would substitute CSAPR compliance for Texas’ reliance on CAIR. The EPA currently plans to issue its final rule in August 2015.

In May 2014, the EPA issued a request for information under the CAA related to SO₂ control equipment at Tolk Units 1 and 2. In December 2014, the EPA proposed to disapprove the reasonable progress portions of the SIP and instead adopt a Federal Implementation Plan. For SPS, the EPA proposed to require dry scrubbers on both Tolk units to reduce SO₂ emissions to help achieve reasonable progress goals the EPA would establish for Texas and Oklahoma national parks and wilderness areas. As proposed, the dry scrubbers would need to be installed and operating within five years of the EPA’s final action, currently expected in August 2015. SPS filed comments in April 2015, opposing the proposal.Whether dry scrubbers are required is dependent on the EPA’s final decision. If required, they would cost approximately $600 million, with an annual operating cost of approximately $10.4 million.

Legal Contingencies

SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Employment, Tort and Commercial Litigation

Exelon Wind (formerly John Deere Wind) Complaint—Several lawsuits in Texas state and federal courts and regulatory proceedings have arisen out of a dispute concerning SPS’ payments for energy and capacity produced from the Exelon Wind subsidiaries’ projects. There are two main areas of dispute. First, Exelon Wind claims that it established legally enforceable obligations (LEOs) for each of its 12 wind facilities in 2005 through 2008 that require SPS to buy power based on SPS’ forecasted avoided cost as determined in 2005 through 2008. Although SPS has refused to accept Exelon Wind’s LEOs, SPS accepts that it must take energy from Exelon Wind under SPS’ PUCT-approved Qualifying Facilities (QF) Tariff. Second, Exelon Wind has raised various challenges to SPS’ PUCT-approved QF Tariff, which became effective in August 2010. On Jan.16, 2015, Exelon Wind filed motions to dismiss or notices of non-suits for its state and federal lawsuits regarding the QF tariff, and for its state and federal lawsuits and regulatory proceedings regarding the LEOs. Later in January, the PUCT and state and federal courts issued orders dismissing the cases. On April 28, 2015, Exelon Wind filed a notice of withdrawal of its complaint regarding the LEOs, which will become effective on May 13, 2015. The only remaining proceeding is pending before the FERC, and involves the QF Tariff.

SPS believes the likelihood of loss in these proceedings is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms. No accrual has been recorded for this matter.

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Income Taxes

3 Months Ended

Mar. 31, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Except to the extent noted below, Note 6 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in March 2016. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of March 31, 2015, the IRS had proposed an adjustment to several federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. SPS is not expected to accrue any income tax expense related to this adjustment. As of March 31, 2015, the IRS has begun the appeals process; however, the outcome and timing of a resolution are uncertain.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of March 31, 2015, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	March 31, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	1.5	$	1.5
Unrecognized tax benefit — Temporary tax positions	12.3		11.7
Total unrecognized tax benefit	$	13.8	$	13.2

The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)	March 31, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(5.5	)	$	(4.8	)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at March 31, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2015 or Dec. 31, 2014.

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Rate Matters

3 Months Ended

Mar. 31, 2015

Public Utilities, General Disclosures [Abstract]

Rate Matters

Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

Texas 2015 Electric Rate Case — In December 2014, SPS filed a retail electric, non-fuel rate case in Texas seeking an overall increase in annual revenue of approximately $64.8 million, or 6.7 percent. The filing was based on a historic test year ending June 2014, adjusted for known and measurable changes, a return on equity (ROE) of 10.25 percent, an electric rate base of approximately $1.6 billion and an equity ratio of 53.97 percent. In March 2015, SPS revised its requested increase to $58.9 million based on updated information.

As part of its request, SPS is seeking a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014.

The following table summarizes the net request:

(Millions of Dollars)	Request
Investment for capital expenditures — post-test year adjustments	$	23.7
Depreciation expense	13.9
Wholesale load reductions	12.0
Purchased power capacity costs	3.2
Other, net	6.1
Total	$	58.9

In April 2015, a revised procedural schedule was established. The next steps are expected to be as follows:

• Intervenor Direct Testimony — May 15, 2015;

• Staff Direct Testimony — May 22, 2015;

• Staff and Intervenor Cross-Rebuttal Testimony — June 8, 2015;

• Rebuttal Testimony — June 10, 2015; and

• Evidentiary Hearing — June 24, 2015.

The parties have agreed the rates will be effective June 11, 2015. A PUCT decision is anticipated in the second half of 2015.

Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Wholesale Rate Complaints— In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, filed a rate complaint alleging that the base ROE included in the SPS production formula rate for Golden Spread of 10.25 percent, and the SPS transmission base formula rate ROE of 10.77 percent, are unjust and unreasonable. In July 2013, Golden Spread filed a second complaint, again asking that the base ROE in the SPS production formula rate for Golden Spread and transmission formula rates be reduced to 9.15 and 9.65 percent, respectively. In June 2014, the FERC issued orders consolidating the Golden Spread ROE complaints and setting the complaints for settlement judge or hearing procedures.

The FERC established effective dates for the refunds as April 20, 2012 (first refund period) and July 19, 2013 (second refund period). Settlement judge procedures were unsuccessful and the complaints were set for hearings. In the first quarter of 2015, Golden Spread, SPS and FERC staff filed their initial testimonies recommending the following ROEs:

	Refund Period	Production ROE		Transmission ROE (a)
Golden Spread	1	8.78	%	9.28	%
	2	8.51		9.01
SPS	1	10.25		10.39
	2	10.25		11.20
FERC Staff	1	8.97		9.47
	2	8.64		9.14

^(a)  Includes a Southwest Power Pool, Inc. (SPP) Regional Transmission Organization (RTO) membership adder up to 50 basis points.

Hearings are scheduled for July 2015. An initial administrative law judge (ALJ) decision is expected to be issued by Nov. 25, 2015, and a final FERC order to be issued no earlier than 2016.

A third rate complaint was filed in October 2014 by Golden Spread, along with certain New Mexico cooperatives and the West Texas Municipal Power Agency, requesting that the ROE in the SPS production formula rates for Golden Spread and the New Mexico cooperatives and SPS transmission formula rate, which includes an SPP RTO membership adder up to 50 basis points, be reduced to 8.61 percent and 9.11 percent, respectively. The complainants requested a refund effective date of Oct. 20, 2014. In January 2015, the FERC issued an order setting the third complaint for hearing procedures and granting the complainants’ requested refund effective date. A hearing is scheduled for October 2015, with an ALJ initial decision expected in January 2016, and a final FERC order following later in 2016.

SPS recorded a current liability representing the current best estimate of a refund obligation associated with potential ROE adjustments as of March 31, 2015, and is reducing transmission and production revenues, net of expense, between $4 million and $6 million annually.

2004 FERC Complaint Case Orders—In August 2013, the FERC issued an order related to a 2004 complaint case brought by Golden Spread and Public Service Company of New Mexico (PNM) and an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS.

The original complaint included two key components: 1) PNM’s claim regarding inappropriate allocation of fuel costs and 2) a base rate complaint, including the appropriate demand-related cost allocator. The FERC previously determined that the allocation of fuel costs and the demand-related cost allocator utilized by SPS was appropriate.

In the August 2013 Orders, the FERC clarified its previous ruling on the allocation of fuel costs and reaffirmed that the refunds in question should only apply to firm requirements customers and not PNM’s contractual load. The FERC also reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3 coincident peak (CP) rather than a 12 CP system.

In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling. In October 2013, the FERC issued orders further considering the requests for rehearing, which are currently pending. As of Dec. 31, 2014, SPS had accrued $50.4 million related to the August 2013 Orders and an additional $1.8 million of principal and interest was accrued during 2015.

2015 Formula Rate Change Filing—In January 2015, SPS filed to revise the production formula rates for six of its wholesale customers, including Golden Spread, effective Feb. 1, 2015. The filing proposes several modifications, including a reduction in wholesale depreciation rates and the use of a 12 CP demand-related cost allocator for all wholesale customers. On March 31, 2015, the FERC accepted this filing, effective July 1, 2015, subject to refund and settlement judge or hearing procedures. The parties are engaged in settlement judge procedures.

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Borrowings and Other Financing Instruments

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for SPS were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			16
Average amount outstanding	2			9
Maximum amount outstanding	31			100
Weighted average interest rate, computed on a daily basis	0.56		%	0.22		%
Weighted average interest rate at period end	N/A			0.45

Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for SPS was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	400		$	400
Amount outstanding at period end	123			37
Average amount outstanding	103			83
Maximum amount outstanding	144			241
Weighted average interest rate, computed on a daily basis	0.44		%	0.26		%
Weighted average interest rate at period end	0.56			0.47

Letters of Credit — SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At March 31, 2015 and Dec. 31, 2014, there were $30 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At March 31, 2015, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	153	$	247

^(a)  This credit facility expires in October 2019.

^(b)  Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the credit facility outstanding at March 31, 2015 and Dec. 31, 2014.

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Rate Matters (Details) (USD $)	1 Months Ended							3 Months Ended
	Oct. 31, 2014	Jul. 31, 2013	Apr. 30, 2012	Mar. 31, 2015	Dec. 31, 2014	Jan. 31, 2015	Aug. 31, 2013 Factor	Mar. 31, 2015
Public Utilities, General Disclosures [Line Items]
Other Liabilities, Current				$ 88,724,000	$ 80,211,000			$ 88,724,000
FERC Proceeding - Wholesale Electric Rate Complaints
Public Utilities, General Disclosures [Line Items]
Public Utilities, Base return on equity charged to customers through production formula rates, Percentage			10.25%
Public Utilities, Base return on equity charged to customers through transmission formula rates, Percentage			10.77%
Public Utilities, Base return on equity requested by customers to be charged through production formula rates, Percentage	8.61%	9.15%
Public Utilities, Base return on equity requested by customers to be charged through transmission formula rates, Percentage	9.11%	9.65%
Public Utilities, Incremental ROE basis point increase (decrease) recommended by third parties	50
Texas 2015 Electric Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount					64,800,000
Public Utilities, Requested Rate Increase (Decrease), Percentage					6.70%
Public Utilities, Requested Return on Equity, Percentage					10.25%
Public Utilities, Requested Rate Base, Amount					1,600,000,000
Public Utilities, Requested Equity Capital Structure, Percentage					53.97%
Public Utilities, Revised requested rate increase (decrease)				58,900,000
Public Utilities, Additional capital investment					392,000,000
FERC Proceeding - FERC Orders
Public Utilities, General Disclosures [Line Items]
Number of components included in regulatory proceeding							2
Other Liabilities, Current					50,400,000
Current year increase (decrease) to pre-tax earnings resulting from regulatory proceedings								1,800,000
Number of customers for which a public utility proposes to revise formula rates						6
Federal Energy Regulatory Commission (FERC) | FERC Proceeding - FERC Orders
Public Utilities, General Disclosures [Line Items]
Number of coincident peaks used as demand allocator, revised							3
Number of coincident peaks used as demand allocator, original							12
SPS [Member] | FERC Proceeding - Wholesale Electric Rate Complaints
Public Utilities, General Disclosures [Line Items]
Public Utilities, Incremental ROE basis point increase (decrease) recommended by third parties								50
SPS [Member] | Wholesale Electric Rate Complaint, Refunds as of April 20, 2012 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, First refund period								1
Public Utilities, Base return on equity requested charged to customers through production formula rates, Percentage								10.25%
Public Utilities, Base return on equity requested charged to customers through transmission formula rates, Percentage								10.39%	[1]
SPS [Member] | Texas 2015 Electric Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Revised requested rate increase (decrease)				58,900,000
Public Utilities, Portion of requested rate increase (decrease) related to post-test year investments in capital expenditures				23,700,000
Public Utilities, Portion of requested rate increase (decrease) related to depreciation expense				13,900,000
Public Utilities, Portion of requested rate increase (decrease) related to wholesale load reductions				12,000,000
Public Utilities, Portion of requested rate increase (decrease) related to purchased power capacity costs				3,200,000
Public Utilities, Portion of requested rate increase (decrease) related to other costs				6,100,000
SPS [Member] | Wholesale Electric Rate Complaint, Refunds as of July 19, 2013 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Second refund period								2
Public Utilities, Base return on equity requested charged to customers through production formula rates, Percentage								10.25%
Public Utilities, Base return on equity requested charged to customers through transmission formula rates, Percentage								11.20%	[1]
SPS [Member] | FERC Proceeding - FERC Orders
Public Utilities, General Disclosures [Line Items]
Number of coincident peaks used as demand allocator, original						12
SPS [Member] | Golden Spread [Member] | Wholesale Electric Rate Complaint, Refunds as of April 20, 2012 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, First refund period								1
Public Utilities, Base return on equity requested by customers to be charged through production formula rates, Percentage								8.78%
Public Utilities, Base return on equity requested by customers to be charged through transmission formula rates, Percentage								9.28%	[1]
SPS [Member] | Golden Spread [Member] | Wholesale Electric Rate Complaint, Refunds as of July 19, 2013 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Second refund period								2
Public Utilities, Base return on equity requested by customers to be charged through production formula rates, Percentage								8.51%
Public Utilities, Base return on equity requested by customers to be charged through transmission formula rates, Percentage								9.01%	[1]
SPS [Member] | FERC Staff [Member] | Wholesale Electric Rate Complaint, Refunds as of April 20, 2012 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, First refund period								1
Public Utilities, Base return on equity requested by the FERC through production formula rates, Percentage								8.97%
Public Utilities, Base return on equity requested by the FERC through transmission formula rates, Percentage								9.47%	[1]
SPS [Member] | FERC Staff [Member] | Wholesale Electric Rate Complaint, Refunds as of July 19, 2013 [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Second refund period								2
Public Utilities, Base return on equity requested by the FERC through production formula rates, Percentage								8.64%
Public Utilities, Base return on equity requested by the FERC through transmission formula rates, Percentage								9.14%	[1]
Minimum [Member] | FERC Proceeding - Wholesale Electric Rate Complaints
Public Utilities, General Disclosures [Line Items]
Public Utilities, Increase (Decrease) of transmission and production revenues, net of expense due to potential ROE adjustments								(4,000,000)
Maximum [Member] | FERC Proceeding - Wholesale Electric Rate Complaints
Public Utilities, General Disclosures [Line Items]
Public Utilities, Increase (Decrease) of transmission and production revenues, net of expense due to potential ROE adjustments								$ (6,000,000)

[1] (a) Includes a Southwest Power Pool, Inc. (SPP) Regional Transmission Organization (RTO) membership adder up to 50 basis points.

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Selected Balance Sheet Data (Tables)

3 Months Ended

Mar. 31, 2015

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	March 31, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	84,817		$	77,465
Less allowance for bad debts	(6,107		)	(5,839		)
	$	78,710		$	71,626

Inventories

(Thousands of Dollars)	March 31, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	25,500	$	24,738
Fuel	6,249		18,493
	$	31,749	$	43,231

Property, Plant and Equipment, Net

(Thousands of Dollars)	March 31, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	5,480,750		$	5,376,606
Construction work in progress	248,921			238,519
Total property, plant and equipment	5,729,671			5,615,125
Less accumulated depreciation	(1,898,627		)	(1,871,984		)
	$	3,831,044		$	3,743,141

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Other Income (Expense), Net (Tables)

3 Months Ended

Mar. 31, 2015

Other Income and Expenses [Abstract]

Other Income (Expense), Net

Other (expense) income, net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2015			2014
Interest income	$	32		$	187
Other nonoperating income	45			—
Insurance policy expense	(133		)	(144		)
Other nonoperating expense	—			(2		)
Other (expense) income, net	$	(56	)	$	41

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015 MWh		Dec. 31, 2014 MWh
Credit Concentration Risk
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	8
Credit Concentration Risk | External Credit Rating, Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	1
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties	7.8
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)	9.00%
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure	6
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties	44.7
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)	50.00%
Credit Concentration Risk | Credit Quality Less Than Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties	1.0
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)	1.00%
Interest Rate Swap
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive losses related to interest rate derivatives expected to be reclassified into earnings within the next twelve months	(0.2)
Electric Commodity (in megawatt hours)
Gross Notional Amounts of Commodity FTRs [Abstract]
Notional Amount	2,954,000	[1]	6,930,000	[1]

[1] (a) Amounts are not reflective of net positions in the underlying commodities.

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STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Derivative instruments:
Reclassification of losses to net income, tax	$ 24	$ 24

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2015

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the financial statements in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

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Benefit Plans and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost (Credit)

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended March 31
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,752		$	2,296		$	239		$	312
Interest cost	5,046			5,111			436			643
Expected return on plan assets	(7,153		)	(6,545		)	(635		)	(812		)
Amortization of prior service cost (credit)	10			14			(100		)	(100		)
Amortization of net loss (gain)	3,772			3,332			(160		)	(80		)
Net periodic benefit cost (credit)	4,427			4,208			(220		)	(37		)
Credits recognized due to the effects of regulation	713			707			—			—
Net benefit cost (credit) recognized for financial reporting	$	5,140		$	4,915		$	(220	)	$	(37	)

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Amount outstanding at period end	$ 123,000,000	$ 37,000,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	100,000,000	100,000,000
Amount outstanding at period end	0	16,000,000
Average amount outstanding	2,000,000	9,000,000
Maximum amount outstanding	31,000,000	100,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.56%	0.22%
Weighted average interest rate at period end (percentage)		0.45%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	400,000,000	400,000,000
Amount outstanding at period end	123,000,000	37,000,000
Average amount outstanding	103,000,000	83,000,000
Maximum amount outstanding	$ 144,000,000	$ 241,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.44%	0.26%
Weighted average interest rate at period end (percentage)	0.56%	0.47%

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Other Comprehensive Income

3 Months Ended

Mar. 31, 2015

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended March 31, 2015			Three Months Ended March 31, 2014
Accumulated other comprehensive loss at Jan. 1	$	(989	)	$	(1,161	)
Losses reclassified from net accumulated other comprehensive loss	42			43
Net current period other comprehensive income	42			43
Accumulated other comprehensive loss at March 31	$	(947	)	$	(1,118	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2015				Three Months Ended March 31, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	66		(a)	$	67		(a)
Total, pre-tax	66				67
Tax benefit	(24		)		(24		)
Total amounts reclassified, net of tax	$	42			$	43

^(a)  Included in interest charges.